Naturally-Fractured Carbonate Research Articles

Research and Application of the Composite Reservoir Stimulation Technology for Ultra-High-Temperature Ultra-Deep Naturally-Fractured Carbonate Reservoirs

The Ordovician buried-hill carbonate reservoir in the northern Jizhong Sag of China is seen with abundance in hydrocarbon resources. Nonetheless, attempts of multiple reservoir stimulation technologies have all failed to make breakthrough, due to its lithological complexity (mixture of dolomite and limestone), ultra-high temperatures (180°C) and high in-situ stress gradients (0.023 MPa/m), Given the aforementioned reservoir geological challenges, reservoir evaluation, technology optimization and plan design starting from the reservoir geological characteristics have been carried out, and the “composite” reservoir stimulation technology for ultra-high-temperature ultra-deep naturally-fractured carbonate reservoirs has been proposed. In terms of the short effective affected distance of acid under high temperatures (180°C), low conductivity sustainability owing to high closure stresses (induced by the burial depth of 5,000 m), extreme difficulties in expanding stimulated reservoir volumes (large lateral in-situ stress differences and long vertical spans), the practice of “multi-stage injection, temporary plugging and diversion, and propped acid fracturing” highlighting high pump rates and combination of low- and high-viscosity fluids (acid and fracturing fluids) has been developed and evolves into the network fracturing technology capable of inter-layer temporary isolation and within-layer diversion. The above technology has been applied in Well AT1x, with high volumes of fluid consumption and the maximum pump rate of 11 m3/min. Safe and efficient operation over six hours featuring challenges such as 3,000 m3 of composite fluids, ultra-high temperatures and ultra-high pressures is achieved. On-site monitoring such as the micro-seismic monitoring and simulation results show that compared with the previous reservoir stimulation, the developed technology presents SRV 3.5 times larger, and results in three-dimensional reservoir reconstruction. The post-fracturing daily gas production amounts to 409,000 m3 and daily oil production, 71 m3. In production testing, the wellhead pressure maintained over 25 MPa, and the daily gas production exceeds 100,000 m3, which indicate stable pressures and production, and a safe wellbore. The application accomplishes the design goal of integrated exploration and exploitation, and geology and engineering, and provides references for reservoir simulation of analogous reservoirs.

Geological Model of a Storage Complex for a CO2 Storage Operation in a Naturally-Fractured Carbonate Formation

Investigation into geological storage of CO2 is underway at Hontomín (Spain). The storage reservoir is a deep saline aquifer formed by naturally fractured carbonates with low matrix permeability. Understanding the processes that are involved in CO2 migration within these formations is key to ensure safe operation and reliable plume prediction. A geological model encompassing the whole storage complex was established based upon newly-drilled and legacy wells. The matrix characteristics were mainly obtained from the newly drilled wells with a complete suite of log acquisitions, laboratory works and hydraulic tests. The model major improvement is the integration of the natural fractures. Following a methodology that was developed for naturally fractured hydrocarbon reservoirs, the advanced characterization workflow identified the main sets of fractures and their main characteristics, such as apertures, orientations, and dips. Two main sets of fracture are identified based upon their mean orientation: North-South and East-West with different fracture density for each the facies. The flow capacity of the fracture sets are calibrated on interpreted injection tests by matching their permeability and aperture at the Discrete Fracture Network scale and are subsequently upscaled to the geological model scale. A key new feature of the model is estimated permeability anisotropy induced by the fracture sets.

Sodium silicate gelants for water management in naturally fractured hydrocarbon carbonate formations

Two commercially available, water-soluble, environmentally friendly, sodium silicate gelant systems (Silicate A and Silicate B) are screened and evaluated for water management applications in naturally fractured carbonate (NFC) reservoirs. The gelant impact on oil production and the ability to reverse poorly deployed gel treatments through gel dissolution are also investigated.Several bulk- and core-based tests are engaged, with the two investigated water-soluble silicate gelant chemicals having undergone a thorough and careful investigation of their filterability, injectivity, gelation time, gel strength, and gel shrinkage. The activators used for gel formation are system dependent and included NaCl, HCl, HNO3, HCOOH, and urea. Gelation is mainly controlled by the activator type and concentration, silicate concentration and temperature. Formed gel strength can be improved by increasing the injected silicate concentration but in Silicate B experiments, gelation difficulties are experienced for concentrations exceeding ∼7wt%.Filterability of Silicate B is significantly better than that of Silicate A. Fractured core tests using Silicate A gelant revealed that the average core permeability is reduced by three orders of magnitude from prior- to post-gelation conditions. Silicate B gelants exhibited gelling “difficulties” and formed gels displayed a lower strength compared to Silicate A gels. Unsuccessfully deployed gels may be reversed through dissolution with alkaline fluids (NaOH or KOH); gel dissolution rate is a function of the alkaline fluid concentration and type of process followed.Overall, Silicate A outperforms Silicate B and shows promising properties for its potential utilization in field applications to control injected water in NFC formations.

Laboratory Testing of Environmentally Friendly Sodium Silicate Systems for Water Management Through Conformance Control

Summary The goal of this work is to screen and evaluate laboratory mixtures of existing commercial, environmentally friendly sodium silicate chemicals that can be used for water management in naturally fractured carbonate (NFC) reservoirs. A thorough evaluation of a chemical for conformance-control purposes requires the investigation of the chemical properties before, during, and after gelation. These properties are the gelant's viscosity, pH, filterability, and injectivity; the gelation time and kinetics of the gelation process; strength of the formed gel against applied external forces; gel stability; gel shrinkage; and post-gelation-time behavior. This investigation has been conducted for different combinations (gelant systems) of sodium silicate with two types of polymers (a xanthan biopolymer and a low-molecular-weight synthetic polymer) and a crosslinker. Measurements on the gelant systems’ viscosity showed that the base sodium silicate system has a low, water-like, viscosity with a Newtonian behavior. This provides significant benefits for matrix treatment, but higher gelant viscosities may be required when sodium silicate gelants are used for conformance control of highly conductive fluid pathways to minimize potential placement difficulties caused by the lack of wellbore control with the possibility of the injected gelant reaching nondepleted formation regions, especially in cases of static gelation. This can be partially addressed by enhancing the gelant's viscosity through the addition of polymers without sacrificing, or even increasing in some cases, the resulting gel strength while at the same time lowering the gelant matrix injectivity. Gelant systems containing biopolymer resulted in a more shear-thinning behavior than other gelant systems, and the measured viscosity/shear-rate data could be well-matched with the Carreau-Yassuda model. Traditional tube testing and dynamic oscillatory tests were performed to measure the gelation time and monitor the gelation process and viscoelastic behavior of the formed gel at various temperatures. Gelation time, a critical factor in the placement of the injected-chemical system, can be tailored to field conditions by adjusting the gelant systems’ contents and concentrations. The strength of the formed gels of various gelant systems were compared on the basis of the results from maximum-compressional-pressure (MCP) tests. Strength tests showed promising gel behavior mainly for two of the selected gelant systems, one of which is the base system (sodium silicate without polymer additives) and the other is a silicate/biopolymer system. Silicate/synthetic-polymer systems, with or without crosslinker, yield significantly weaker gels. More-detailed investigations are needed, mostly on the interpretation of the tests, to be able to upscale the laboratory results to field applications. In addition to bulk measurements, coreflood tests were also conducted in artificially fractured carbonate cores to investigate gel-isolation effectiveness and formed-gel stability and shrinkage at static gelation conditions. Although some shrinkage was observed over time in practically all core laboratory experiments, the resulting core average permeabilities in post-gelation floods were significantly lower than the original fracture rock sample permeability. This was observed especially in the base sodium silicate and the silicate/biopolymer systems that were engaged to isolate the artificial core sample “fracture.” Systems containing synthetic polymers resulted in more shrinkage.

Rheological evaluation of a sodium silicate gel system for water management in mature, naturally-fractured oilfields

Abstract Excess water production is a common problem in mature and hydrocarbon rate declining oil and gas fields. Increased water production rates reduce oil and gas production, increase the cost related with fluid lifting, handling and disposal of produced water, and negatively influence the hydrocarbon production economics. Among the various existing techniques for water control, silicate gel systems are known to be an effective and environmentally friendly method for managing water production. The gel systems usually contain two main components, the liquid silica and activator. The low-viscosity (almost like water) system, which is mixed and pumped from surface in a liquid form, is designed to gel under reservoir conditions, thus allowing sufficient time for the pumped fluids to reach the designated location from the treatment well. This work focuses on the laboratory qualification of a commercially available sodium silicate system for designing and implementing field water shutoff treatments in mature, naturally-fractured carbonate formations. Lab rheology measurements are carried on sodium silicate gel samples using the Anton Paar Rheometer MCR302. Two test modes are run with the specific purposes: the Dynamic-Mechanical (DMA) mode is employed to determine the onset of gelation (sol–gel transition time or gel point) and the viscosity increase versus time; the Amplitude Sweep (AS) mode is used to assess the formed gel's shear strength at a given viscosity. Gel point and gel strength play an important role in designing successful water shutoff treatments since the first determines the required time for the injected gelant system to gel into reservoir and other determines the forces the formed gel can withstand under shear conditions. The effects of silicate and activator (NaCl solution) concentrations, presence of divalent ions (e.g., Ca 2+ , Mg 2+ ), temperature, and gelant dilution on sol–gel transition time are investigated. A general correlation is derived that describes the relation between sol–gel transition times and silicate solution concentration, activator concentration, temperature, degree of water dilution, and concentration of divalent ions. This correlation can be used to design the recipe of the silicate system for applications in fields with treatment region temperatures in the range of 40–60°.